Jay R. Wilson - Vice President of Investor Relations John B.

Hess - Chief Executive Officer and Director Gregory P. Hill - President of Worldwide Exploration & Production and Executive Vice President John P.

Rielly - Chief Financial Officer, Principal Accounting Officer and Senior Vice President

Edward Westlake - Crédit Suisse AG, Research Division Douglas Terreson - ISI Group Inc., Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Paul Sankey - Deutsche Bank AG, Research Division Brandon Mei - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Paul Y.

Cheng - Barclays Capital, Research Division John P. Herrlin - Societe Generale Cross Asset Research Pavel Molchanov - Raymond James & Associates, Inc., Research Division Phillips Johnston - Capital One Securities, Inc., Research Division

Thank you, Crystal. Good morning, everyone, and thank you for participating in our third quarter earnings conference call.

Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws.

These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess' annual and quarterly reports filed with the SEC.

Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.

With me today are John Hess, Chief Executive Officer; Greg Hill, President and Chief Operating Officer; John Rielly, Senior Vice President and Chief Financial Officer. I'll now turn the call over to John Hess.

Thank you, Jay, and welcome to our third quarter conference call. I will make some high-level comments on the quarter and the progress we are making in executing our strategy to become a pure play E&P company.

Greg Hill will then discuss our E&P operations, and John Rielly will go over our financial results. Net income for the third quarter of 2013 was $420 million or $405 million on an adjusted basis.

Adjusted earnings per share were $1.18 compared to $1.46 in the year-ago quarter. Net production in the third quarter averaged 310,000 barrels of oil equivalent per day compared to 402,000 barrels of oil equivalent per day in last year's third quarter.

Asset sales associated with our strategic portfolio reshaping accounted for 83,000 barrels of oil equivalent per day of the decline. The remainder was primarily related to unplanned downtime in Libya, resulting from the civil unrest in that country and heavier-than-normal seasonal maintenance in the Gulf of Mexico, partially offset by higher production from the Bakken and Valhall.

Our plan is on track to build a higher-growth and lower-risk E&P portfolio, capable of delivering a 5-year compound annual growth rate of 5% to 8% off of our pro forma 2012 production base. This growth is underpinned by the Bakken in North Dakota, the Valhall Field in Norway, the North Malay Basin Project in Malaysia, the Tubular Bells Field in the Gulf of Mexico and the Utica Shale in Ohio.

Net production from the Bakken averaged 71,000 barrels of oil equivalent per day, up 14% from the third quarter a year ago. Our full year 2013 production forecast for the Bakken remains 64,000 to 70,000 barrels of oil equivalent per day.

In the third quarter, we continued to reduce Bakken well cost, which declined to $7.8 million, down 18% from a year ago. In Norway, production from the Valhall Field ramped up strongly following completion of a multi-year field redevelopment in the first quarter.

Net production averaged 37,000 barrels of oil equivalent per day in the third quarter versus 7,000 barrels of oil equivalent per day in the year-ago quarter. In Malaysia, we recently achieved first gas at the Hess-operated North Malay Basin Project.

Net production is expected to reach 40 million cubic feet per day during the fourth quarter and remain at this level through 2016. Full field development is expected to increase net production to 165 million cubic feet per day by 2017.

In the Deepwater Gulf of Mexico, the Hess-operated Tubular Bells development is on track to achieve first production in the third quarter of 2014 at a net rate of approximately 25,000 barrels per day. In Ohio, delineation of the wet gas window of the Utica Shale will continue through 2014.

Initial well results have been encouraging, and we expect to commence development in 2015. Integral to our transformation to a focused pure play E&P company is our divestiture program, where we continue to make significant progress.

In July, we announced the sale of our Energy Marketing business to Direct Energy for more than $1 billion. And earlier this month, we announced the sale of our Terminals business to Buckeye Partners for $850 million.

In addition to proceeds from the Terminal sale, this transaction will free up approximately $900 million of working capital through inventory liquidation. We expect both transactions to close in the fourth quarter.

Year-to-date, we have announced or completed 6 of 10 planned divestitures with sales proceeds and the release of working capital totaling $6.3 billion. The remaining divestitures are well underway for our upstream assets in Indonesia and Thailand, as well as our Retail Marketing and Trading businesses.

Following the announcement of the sale of our Energy Marketing business at the end of July, we commenced our previously announced share repurchase program. Through October 29, we have repurchased 11.2 million shares for $882.7 million.

Also in September, our annual dividend increased by 150% to $1 per share. In closing, we are pleased with the progress we have made in our transformation to become a pure play E&P company and in the execution of our plan to reshape our portfolio.

We are committed to continuing to review all options to optimize our portfolio and allocate capital to generate the highest financial returns for our shareholders. I will now turn the call over to Greg for an operational update.

Thanks, John. I would like to provide a brief review of the progress we are making in executing our EP strategy.

Starting with unconventionals. In the third quarter, net production from the Bakken averaged 71,000 barrels of oil equivalent per day, which was up 14% from the third quarter of 2012.

As we indicated previously, our Bakken production ramps up in the second half of the year, as a result of the completion of our transition to pad drilling. As previously disclosed, there will be planned downtime in the Bakken during the fourth quarter, as we complete the expansion of the Tioga Gas Plant.

This downtime is incorporated into our 2013 Bakken production guidance, which remains 64,000 to 70,000 barrels of oil equivalent per day. In terms of individual Bakken well performance, we remain focused on driving superior financial returns, which is a function of well cost, productivity and price realizations.

Drilling and completion costs in the third quarter averaged $7.8 million per well versus $8.4 million in the previous quarter. In addition, the productivity of our wells continues to be among the highest in industry.

During the quarter, we brought 50 operated wells on to production, of which 30 were Middle Bakken and 20 were Three Forks. For the full year, we expect to bring approximately 170 wells on production, with 2/3 targeting the Middle Bakken and 1/3 targeting the Three Forks.

As a result of our continuing delineation in Three Forks, both the productivity and aerial extent of the formation has increased above our previous estimates. In addition, the results of our infill pilot programs and reservoir modeling have led us to believe both the Middle Bakken and Three Forks can be further downspaced.

We believe that it will be economically attractive to increase the well count and the majority of our Middle Bakken acreage from 5 wells per 1,280 drilling -- acre drilling unit to 7. Similarly in those areas where the Three Forks is perspective, we believe the well count can be increased from 4 wells per 1,280 acre drilling unit to 6.

Over the next 12 months, we plan to install 17 well pads in this new configuration to obtain additional data before making a final decision to move to this tighter spacing. As we make further progress in our planning and field testing, we will provide updated guidance for production, drilling locations and resource potential.

Our Tioga rail facility ran at capacity in the third quarter, delivering an average of 54,000 barrels per day to higher-value markets. Our Tioga Gas Plant expansion project, which will increase wet gas input capacity from 120 million to 250 million cubic feet per day is on schedule to begin commissioning at the end of 2013, enabling us to capture more liquids and value from our own gas and from third parties.

In summary, we're on track to deliver our 2013 production and capital guidance for the Bakken, and we are increasingly confident about the long-term upside potential. Turning to the Utica.

The appraisal of our acreage continues, and we are encouraged by well results to date. In 2013, Hess and CONSOL expect to drill 25 wells across both our 100% owned and joint venture acreage.

In the third quarter, we drilled 7 wells, completed 8 and flow tested 1 well. On our 100% owned acreage, the Porterfield C 1H-17 well in Belmont County tested at a 24-hour rate of 3,421 barrels of oil equivalent per day, including 21% liquids.

Regarding exploitation, progress continues at Valhall, North Malay Basin and Tubular Bells. At the BP-operated Valhall Field in Norway, in which Hess has a 64% interest, net production averaged 37,000 barrels of oil equivalent per day in the third quarter.

Full year 2013 net production from Valhall is forecast by the operator to be in the range of 24,000 to 28,000 barrels of oil per day, which we believe will come in at the lower end of this range. At North Malay Basin in the Gulf of Thailand, where Hess has a 50% working interest and is operator, we completed the initial 5 development wells ahead of schedule and achieved first gas on October 11 from the early production system.

Net production is expected to reach 40 million cubic feet per day during the fourth quarter and remain at this level through 2016. Full field development is expected to increase net production to 165 million cubic feet per day by 2017.

At our 57% owned and operated Tubular Bells development in the Deepwater Gulf of Mexico, our third production well was drilled during the quarter, and we are on track for field start up in the third quarter of 2014, delivering 25,000 net barrels of oil equivalent per day of high-margin Gulf of Mexico production. Of the 3 wells drilled to date, one came in as expected in terms of pay count, and the other 2 wells came in with substantially higher pay counts.

As a result, we plan to now drill a fourth well to delineate the additional upside identified. In terms of exploration in the Deepwater Tano Cape Three Points Block in Ghana, where Hess has a 90% working interest and is operator, we have opened a data room and expect to receive bids from potential partners later in the fourth quarter.

Our appraisal plans are currently awaiting final approval from the Ghanaian government. Following approval of both the appraisal program and partnering arrangements by the Ghanaian government, we plan to issue guidance as to the resource potential on the block, as well as detail our appraisal program.

In Kurdistan, where Hess has a 64% working interest and is operator of the Shakrok and Dinarta blocks, we spudded the first of 2 planned exploration wells in August and anticipate spudding the second well in the fourth quarter. In closing, our focus remains on executing our strategic plan to improve capital efficiency and deliver higher sustainable financial returns to our shareholders.

I will now turn the call over to John Rielly.

Thanks, Greg. Hello, everyone.

In my remarks today, I will compare results from the third quarter of 2013 to the second quarter of 2013. Corporation generated consolidated net income of $420 million in the third quarter of 2013 compared with $1,431,000,000 in the second quarter of 2013.

Adjusted earnings, which exclude items affecting comparability of earnings between periods, were $405 million in the third quarter of 2013 and $520 million in the previous quarter. Our third quarter earnings were reduced by approximately $105 million due to an underlift of production and downtime in the Gulf of Mexico.

In addition, higher DD&A and deferred taxes in the quarter resulted from increased production from the Valhall Field. Turning to Exploration and Production.

E&P had income of $455 million in the third quarter of 2013 and $1,533,000,000 in the second quarter. E&P adjusted earnings were $458 million in the third quarter of 2013 and $600 million in the previous quarter.

Second quarter income included a nontaxable gain of $951 million related to the sale of the corporation's 90% interest in its Russian subsidiary, Samara-Nafta. Third quarter and second quarter results included after-tax charges of $3 million and $18 million, respectively, for employees severance and exit cost.

Changes in the after-tax components of adjusted earnings between the second and third quarter were as follows. Lower sales volumes decreased earnings by $177 million.

Higher depreciation, depletion and amortization decreased earnings by $16 million. Lower exploration expenses increased earnings by $22 million.

Lower cash costs increased earnings by $17 million. Changes in realized selling prices increased earnings by $8 million.

All other items net to an increase in earnings of $4 million, for an overall decrease in third quarter adjusted earnings of $142 million. Our E&P operations were underlifted compared with production by approximately 1.2 million barrels of crude oil in the third quarter, resulting in decreased after-tax income of approximately $30 million.

The downtime for extended seasonal maintenance at non-operated fields in the Gulf of Mexico lowered production by approximately 20,000 barrels of oil equivalent per day and reduced third quarter income by approximately $75 million compared with the second quarter. In addition, higher depreciation expense in the quarter reflected a greater production contribution from the Valhall Field, which has a higher DD&A rate per barrel than the portfolio average, resulting from a combination of the recently completed field redevelopment project to install the new production platform and prior acquisition cost.

While the higher DD&A rate and the high Norwegian tax rate lowers Valhall's net income per barrel contribution to the portfolio, Valhall's cash margin per barrel is accretive to the portfolio average, as we expect cash taxes to be deferred for the next several years. The cash margin per barrel of the portfolio was $54 per barrel in the third quarter versus $51 in the second quarter, primarily due to higher realized prices, increased Valhall production and lower production from Libya.

The E&P effective income tax rate, excluding items affecting comparability of earnings, was 45% for the third quarter and 44% in the second quarter of 2013. The cash tax rate was 16% in the third quarter and 23% in the second quarter.

This improvement in the cash tax rate was also driven by the change in production in Valhall and Libya. We are updating our guidance as a result of the shut-in production in Libya.

Libya's contribution to net income and cash flow is not material. However, the reduction in production will have the effect of increasing our unit cost and decreasing our tax rate.

Our updated production guidance assumes no further contribution from Libya for the remainder of 2013 due to current civil unrest in the country. In addition, maintenance at the Auger platform kept the Llano Field shut in at the month of October.

As a result, we expect fourth quarter 2013 production to be approximately 320,000 barrels of oil equivalent per day, and therefore, our full year 2013 E&P production is expected to be at the lower end of the guidance range of 340,000 to 355,000 barrels of oil equivalent per day. In addition, due to the absence of low unit cost barrels from Libya, fourth quarter 2013 cash cost and DD&A expense are each expected to be in the range of $24 to $25 per barrel.

And our full year guidance for total unit cost is being increased to $44 to $45 per barrel from our earlier guidance of $40 to $42 per barrel of oil equivalent. The increase in unit cost per barrel is expected to be largely offset by a reduction in the effective tax rate due to the loss of Libya's high tax production.

The E&P fourth quarter 2013 effective tax rate is expected to be in the range of 39% to 41%, and our full year guidance is being reduced to 42% to 44% from the earlier guidance of 46% to 50%. Absent the impact of changes in commodity prices, our cash margin on a per barrel basis is expected to increase in the fourth quarter with the return of high margin production in the Gulf of Mexico and the absence of our Libyan production, which has cash margins well below the E&P portfolio average.

Turning to our supplemental information. We have posted a supplemental earnings presentation on our website, which has been updated this quarter to include new operational data for our Utica Shale operations in Ohio.

We have added 2013 rig and well counts, details on average net revenue interest percentages, acreage positions and well test results. All data has been split between our joint venture and 100% owned interest.

In addition, pro forma E&P results now include both current and deferred taxes. Turning to Corporate.

Corporate expenses after income taxes were $35 million in the third quarter of 2013 and $50 million in the second quarter. Second quarter Corporate expenses include proxy solicitation cost for the annual shareholders meeting and higher professional fees.

After-tax interest expense was $54 million in the third quarter of 2013 and $63 million in the second quarter, due to higher capitalized interest and lower average outstanding borrowings. Turning to discontinued operations.

Earnings from the Downstream businesses were $54 million in the third quarter of 2013 compared with $11 million in the second quarter. Third quarter results included net after-tax income of $23 million from items affecting comparability of earnings between periods compared with after-tax charges of $21 million in the second quarter.

Turning to our capital return to shareholders. During the third quarter of 2013, the corporation increased its quarterly dividend 150% to $0.25 per share and purchased approximately 6,530,000 common shares at an average price of $76.60 for a total cost of approximately $500 million.

Turning to cash flow. Net cash provided by operating activities in the third quarter, including a decrease of $143 million from changes in working capital, was $1,254,000,000.

Capital expenditures were $1,431,000,000. Common stock acquired and retired was $500 million.

Net borrowings were $372 million. Common stock dividends paid were $85 million.

All other items amounted to a decrease in cash of $14 million, resulting in a net decrease in cash and cash equivalents in the third quarter of $404 million. We had $321 million of cash and cash equivalents at September 30, 2013, and $642 million at December 31, 2012.

Total debt was $6,209,000,000 at September 30, 2013, compared with $8,111,000,000 at December 31, 2012. And the corporation's debt to capitalization ratio was 20.7% at September 30, 2013, compared with 27.7% at the end of 2012.

This concludes my remarks. We will be happy to answer any questions.

I will now turn the call back to the operator.

Yes. A quick question, just on the retail.

I guess if you're going to spin that out, you're going to do, I guess, get a private letter ruling from the IRS. Can you give us any updates on where you are in terms of the mechanics of the retail?

Well, first, we're doing a parallel process. We're going to go down the process of looking at a potential public market option, like you had mentioned, as well as go through an M&A process.

So we're going to go through both of that, and we're going to maximize value to shareholders. As far as the private letter ruling and what we're doing for filing with the SEC, we're kind of on track.

Everything is moving along according to schedule, and we anticipate getting that and get some further information out later this quarter and into early 2014.

Okay, very clear and very helpful. Just coming to the Bakken.

Maybe, Greg, thanks for giving us the initial thoughts on down spacing. Maybe any color on whether you can go beyond that.

Obviously, some of the other companies are hoping to downspace much further. That would be helpful.

Yes. So just in terms of down spacing, our base design has been 9 wells per 1,280-acre DSU.

So that's 5 wells in the Middle Bakken, and 4 on the Three Forks. So that yields effectively a 250- and 320-acre well spacing, respectively.

Now based on the results of our infill pilot programs, we think that we can further downspace with minimal interference. So over the next 12 months, we're going to install tighter spacing at 17 of our DSUs, with 7 wells in the Middle Bakken and 6 in the Three Forks.

So this will bring the spacing down to 180 acres in the Middle Bakken and 210 acres in the Three Forks. So again, moving from 250 to 180 in the Middle Bakken and 320 to 210 in the Three Forks.

And maybe just a quick follow on. That I guess is the 2014 program, but would you then go for deeper spacing once you've established the results of that across the acreage.

Yes. I mean, if -- assuming it all works as expected, then we would go full-scale with the tighter infill program on a go-forward basis.

Sorry. So would you able to downspace to a tighter level than the 7 and 6?

Or...

Potentially. We're going to test a couple of DSUs in an even tighter configuration next year.

So it appears that upside is clearly unfolding in the Bakken in Europe and specifically Valhall looks like production and gas margins are headed higher there too. But at the same time, it also seems like there could be upside potential at Valhall when you consider the recovery rates in some of the neighboring fields.

And so my question's whether you consider the opportunity for improved recovery on Valhall, intermediate to longer term, to be real and why or why not is this is obviously a pretty significant part of the portfolio these days.

Yes, Doug. Just to be clear, we have not been happy with BP's performance as operator of Valhall.

And recently as you know, we had, Greg and I, a senior meeting with BP's leadership to express our concerns. We have worked with them to jointly develop a performance improvement plan, and the results are beginning to show.

The facilities have begun to run more reliably, and production is currently averaging the year net 40,000 barrels of oil equivalent per day. The prize, as you rightly point out, at Valhall remains significant, with a net remaining recoverable resource to our company of more than 500 million barrels.

Our primary focus is to work with BP to grow production over the coming years and leverage our chalk reservoir drilling and completion capability we've developed in South Arne in Denmark. While we're encouraged by the recent progress, if performance does not continue to improve, we'll consider our strategic options.

Greg, I wonder if I could take you back to the Bakken for a second. So you talked about the well pattern changing I guess the 7 and 6.

You haven't talked about deeper benches. Continental obviously talks about second, third and fourth benches.

That's the reason for-- I'm just pointing out the additional down spacing, and neither have you addressed your longer-term production guidance or resource estimates based on the old pattern. So if that's changing can you give us some color as to how you think about the longer-term targets.

And I've got a follow-up please.

Yes, sure, you bet. So let's take it in order.

So let's talk about the Three Forks first, Doug. So as you know, we've continued to delineate the Three Forks in 2012 and 2013.

And so by the end of this year, we should have about 140 Three Forks wells drilled and on production. So that's proved up some 40% of our 550,000 to 600,000 core acres.

And we expect ultimately that some 60% to 65% of our core acreage is going to be economic for the Three Forks. Results on the Three Forks have been great.

So results to date have exceeded our expectations. And in fact, our well results, coupled with the publicly available production data, show that our Three Forks acreage is among the best in the play.

So a little context on where we are in the Three Forks. Regarding the benches, we do see several discrete thicker packages in certain areas of the field, where we will plan to test whether or not more than one well in the Three Forks actually can deliver superior returns.

And so we'll test that next year as part of our 2014 plan. Now in reference to the longer-term potential of the Bakken, if you think about where we are today so in a 5 and 4 configuration, that yields about 2,500 future drilling locations and about 1 billion barrels of recoverable resource.

Also because of the performance of the Three Forks, that long-term 120,000 barrels a day guidance is going to go up, and we plan to give some more color on that when we issue our annual guidance at the first of the year. Now regarding 7 and 6, obviously, those numbers will go up again.

So the well counts will go up. The resource will go up.

The long-term production will go up further above the Three Forks correction. As we get data from our pilots and drill our wells and get them on production, see the pressure response, then we'll give a second upgrade to the guidance in 2015.

Can you talk about the pace, Greg, in terms of rig count. In light of all of the above, I'm assuming the current pace will accelerate.

Sure. Now we haven't finalized our budget yet.

So I'll put that caveat on it. But this year, we're at 14 rigs.

We plan on increasing that to 17 rigs next year. And then if the 7 and 6 works, assuming it does, and we're confident it will, then you'll see a step to rig count up to 20 rigs a year after and potentially higher after that.

Great. My follow-up is a little bit quicker.

I guess it's to either of the Johns. The pace of buybacks, it seems like a sizable buyback, but didn't really impact the share count too much.

So I'm just wondering if you could help us with what was going on in the timing during the quarter and how you see the pace of buybacks on a go-forward basis, largely, over the next 12 months. I'll leave it there.

Sure. In the quarter, and I think you said it.

It really was the timing. We started -- we didn't start from the beginning of the quarter buying back shares.

So we were buying back more in August and September. There's also when you look at the dilutive effect, obviously, our share price has been increasing.

So from a dilution standpoint, that adds more shares into the calculation as well. So that's why you're not seeing it begin to flow through again in the fourth quarter, as we continue.

So going forward, from a pace standpoint, we are going to continue to be disciplined on the pace. What we've done with our share buyback, as we said before, is we started out because from the Energy Marketing sale of $1 billion, we're tying our buybacks to the proceeds.

So with that $1 billion, we started on that plan, we've now announced the Terminal sale from that. So we'll continue on at this disciplined pace, buying back stock.

I wondered if you could provide us with an update on pricing and realizations there. And if there's some sort of rule of thumb for now and going forward as to how the oil will price there.

Unfortunately, Paul, there really isn't a rule of thumb. So in prior quarters or even going back into late last year, you had the big spread on the Brent TI.

So obviously, moving -- excuse me, moving by train, getting to the coast, you got a bigger uplift from the price realizations. Those have come in.

We're still making money on the rail. In the quarter, probably added around $3 per barrel to our realizations from the rail, but obviously, they've squeezed.

Now Clearbrook and local pricing in Western North Dakota versus WTI, it's going to move based on what's happening in the market. So we're still planning to use all 3 market options, going south to St.

James, going East and West with our crude. And it's going to just factor in to where the price realizations are at the time.

Yes, just a little more color there. During the quarter, the WTI Brent spread narrowed.

I think TI actually, for a couple of days, was over Brent. As you know, right now, TI is probably about $10 under, and there's a further discount at the wellhead for our North Dakota production.

So the rail facility continues to add value to our net backs. How you can get a rule of thumb given the variability just in the third quarter is next to impossible.

The good news is our company is competitively positioned versus, I think, anybody else to maximize the value of our production there, and we continue to do that. Up to 54,000 barrels a day we're moving by rail right now.

About 1/3 is going to the East and West Coast, and the balance goes to the Gulf Coast. And as the East and West Coast increase their ability to receive crude and assuming those markets are more favorable than the Gulf, we'll be able to exploit those opportunities even more in the future.

That's extremely helpful. Firstly, could you indicate the -- just remind us, the cost or the net back that you get when you move to those markets.

So I guess you'd be pricing off the crudes in those given coastal markets, how much less do you get for the transport cost in each case? And secondly, where will we expect to be in terms of your ability to move crude out away from Clearbrook, let's say, next year or at a given point in the future?

Why not say the end of 2014?

The East and West Coast trade more on a Brent basis, and the transportation cost is not materially different. It's a little higher to the East Coast, a little less to the West Coast, but that's figured out in the differentials that you get, but it's more Brent based, where the price you get in the Gulf Coast could be tied to Brent, could be tied to LLS.

And as always, Paul, we'll be situated to maximize value according to what market signals that we get.

And the future development of your ability to move, John?

I'm sorry.

I'm just wondering how much you're going to be able to move to the coast, let's say, in a year's time.

That's going to be more a function of the different refineries on the East and West Coast ability to take unit trains. Right now, there are a few.

And as they improve their capability, we'll be able to do more. Right now, it's sort of limited to that 1/3 that I mentioned of the 54 a day.

If the markets improve, hopefully that number will increase. And quite frankly, if the train differentials still give us better value, we can look at getting a few more trains if we need that, in addition to the 9 unit trains that we already have.

That's very helpful. And my follow-up is, can you update us just on the latest timing for the sale of the Asian assets if we're expecting some news before the end of the year.

Yes, we're well advanced, and more than that we're really not in a position to say. I know there's some big news out there.

I don't want to front run the sale process, but it's well advanced.

I appreciate the color on the production guidance post 2013. I was just wondering if you can give some corresponding guidance to the CapEx?

And also with the ramp and Bakken down spacing and CapEx there, how does that affect your total plan?

Going forward, in 2014, I mean, obviously we'll give our full guidance after we've gone through our budget process here in the fourth quarter, but the guidance we've been given is that the capital spend will have a 5 in front of it. So a 5 handle.

That's basically the only guidance that we've given out right now for 2014. And again, now early days on the Bakken, but what we've basically -- you heard from Greg earlier that we do plan, at least right now, to add some rigs to the Bakken.

However, from an overall capital spend in the Bakken standpoint, that's not necessarily increasing our spend there because we are spending a lot on infrastructure this year in 2013. And as you know, getting the Tioga Gas Plant, we're actually going to have to shut down and commissioning here towards the end of this year.

So the infrastructure spend will be moving more to drilling, keeping the Bakken capital number around the same. So that's general guidance here for '14.

Can you remind us what the CapEx was on infrastructure in the Bakken for 2013?

Yes. It would be between $500 million and $600 million.

Okay. And then one more for me.

Can you quantify the RIN contribution this quarter?

Yes. It was $28 million after-tax that we did recognize the benefit from in the third quarter from RINs.

Now where current pricing is, we're expecting an immaterial contribution in the fourth quarter.

I think -- a number of quick question then. John Rielly, will you be willing to share with us what is the Energy Marketing and Terminal EBITDA or pretax income or after-tax income, whatever is the metric in the third quarter?

No, Paul. We haven't been giving that information out.

So, I mean, you saw with the announcement from Direct on where they had the EBITDA number for the Energy Marketing business. And then as far as Terminals, no, we are, again, it's commercially sensitive here as we go through the transaction with Buckeye.

All right. And, Greg, Bakken continue to improve.

As of this point, from a productivity improvement standpoint, do you think that you already captured the bulk of that order? Do you think that you're just scratching that surface and then there's far more to go?

Well, in terms of -- first on the cost, as you mentioned, the Bakken continues to improve. So our well cost went from 8.4 to 7.8 in a quarter, and that's a result of our application lean manufacturing to just continue to drive improvement.

I think on the productivity side, I mean, we are constantly testing various things to try and improve the productivity and also bring the cost down as well. So there's that kind of -- there's a sweet spot, I call it, where cost and productivity meet to drive the highest return.

So we're focused on drilling the highest return Bakken wells, not necessarily the highest production or not necessarily the lowest cost. We're really trying to find that maximum return point in the Bakken.

And, Greg, or then maybe it's for John, you guys very kind to give a lot more information in Bakken, including the well cost. How about on the cash operating cost?

Is that something that you guys may consider start giving out that information?

That's a currently -- and I know, Paul, we've discussed this before. At this point, just to give you the same guidance is that on the cash cost, which includes production and severance taxes in there, the Bakken is slightly below our portfolio average there from all-in cash costs there.

Going forward, we're looking at -- we're continuing to add information there. Obviously, you know we've got the whole, we're looking at the midstream and the marketing up there in North Dakota.

So it's something we'll still be considering as we move forward to provide that information.

And, Greg, on the gas plant tie in that how many days the Bakken production operation will be impacted?

Well, Paul, it's mainly gas. So we'll send a lot more gas to flare, right?

The liquids will be a very small number, a couple of thousand barrels a day for the quarter, 1,000 to 2,000 barrels a day. So the impact to oil is very small.

Okay. So that means that your fourth quarter Bakken production should not be really materially impacted by this shutdown?

That's right.

So we just continue to see them going higher, may not be going as much of the sequential increase as from second to third, but should not be flat.

Just to add to that Paul, I mean, with the gas and the shutdown, we are -- in that number that I gave out earlier the 320,000 barrels a day, we are seeing Bakken essentially flat with that number -- in that number that I gave, just because due to the shutdown and the shut in of gas.

Any reason that they should be? Because shut-in the gas that you may be losing, say, in the third quarter, is 44 million cubic feet per day, but you're not going to shut down for the entire quarter is it?

No, we aren't. It will go down probably the third week of November.

We're still just finalizing all that. The gas plant will go down, and then we'll start commissioning the plant at the end of the year.

Right. So it will be 1.5 months old.

Your job say 25 -- a 25 million cubic feet per day, or that 4,000...

Yes, 6 weeks. Yes.

And that you typically grow by, say, maybe somewhere in the 5 to 6. So...

Well, I think importantly, Paul, what we said in the opening remarks, all that's built in to our guidance, it's 64 to 70 on the Bakken. That's all built in.

So that range is still very valid.

And, Greg, on Utica, in order for you to come to the commercial development decision, what is the steps or what kind of condition that you need to, to be met, before you can get to that decision?

Well, I think, certainly, with the wet gas, we will be making that decision at the end of 2014 once we finish delineation, and remember that is all HBP in FEED or fee acreage. And it effectively has no royalty.

So the economics of that are very strong, and so we've already moved to pad drilling in a number of well locations. So we're effectively delineating and developing at the same time.

But as far as a full field sanctioned decision, that will come at the end of 2014 as part of our budgeting process. So that's the plan, but the wells are looking great, and the economics look really well with that kind of a royalty.

Yes, can you remind me that how -- what is your net acreage position for the wet gas area?

Well, yes, okay, it's 73,000 currently net acres on the JV acreage. Now, not all of that's wet gas.

So about 30,000 or so, 30,000 to 35,000 will be wet gas acreage. The rest is oil acreage that we don't have any plans to develop on the far West.

I see. And then a -- a final one.

Australia, any update on the long-term gas supply agreement?

Yes. So we continue to make progress.

We're pleased with the progress that we are making on Australia, and we're closer than we ever have been. That's about all I can say at this point.

I know you can't say much about the Asian sale, but what about tax efficiency of the sale? Do we expect a big tax bite?

Again the guidance I've been giving is that from overall proceeds that the cash tax effect will be less than 5%, and that is driven by the Asian sales over there. So there is some leakage with the Asian sales, but again from our overall proceed numbers that we're talking about it's less than 5%.

Okay. One for Greg, in terms of the Utica.

Is your line demarcating the wet gas, dry gas kind of moving a little bit more to the east in terms of the wet gas? Because you had some wells here on your map that had reasonable liquids content that you had in the dry area.

Yes, I think between our wells and industry wells, those lines are constantly moving. They're not moving tens of miles or hundred of miles.

So you're kind of on the edge here of trying to find that window. In the Western part of the dry gas window, which is kind of that transition area from the dry gas to wet gas, those liquids are predominantly NGLs.

And then as we move further West, towards Harrison County and West Belmont County and the East Guernsey County, those total liquids percentages gradually increase to around 60% and then the condensate portion of these liquids goes as high as 35% when you get over there. So you can begin to see where the real sweet spots are, and we're right in the heart of it.

Great. Last one for me is on Ghana.

Would you go solo if need be?

I'm sorry. Could you ask that question again?

Ghana, say you don't find a partner in terms of the PO, would you go solo in terms of the development there?

Well, I think we're committed to the appraisal program certainly. However, I will say that the data room's been very active.

So we anticipate getting bids sometime in November. So.

First on Kurdistan, on the first prospect, do you guys have a pre-drill estimate for that?

We do, but we typically don't give those out for pre-drill.

Any order of magnitude?

No, obviously, if we have a discovery, we'll give you some color on that in the first quarter.

Okay, fair enough. On the Utica, you mentioned still about a year away from kind of FFID decision-making.

Your guidance, over the next 5 years, just to clarify, does not ascribe any credit for the Utica, correct?

No. It does.

For the wet gas portion, which, as Greg said, we started some pad drilling. We are drilling and hooking up wells there.

We do have a contribution from the wet gas portion of the Utica in that guidance.

Okay, but nothing else for the play?

Correct.

Just a follow-up on Doug's question regarding the lower Three Forks benches. I thought some of the 55 wells that were planned for this year were actually targeting the second bench.

So I just wanted to clarify comments, which sounded like so far you haven't really tested any of the lower benches and just as a follow-up I was wondering what the mix might be for next year's Three Forks wells in terms of what percentage might be drilled into the first, second, third or fourth benches.

Yes. So just to clarify, I think what we said was yes, we wanted to target those lower benches, but what we did this year was go down and get core from a lot of those locations.

And as I said in my remarks, it does appear that there are certain parts of the field where you do have 2 big thick sections of the Three Forks. So we plan to actually put horizontals in some of the second bench areas next year.

Now, I will say once again, I think, ultimately the decision on multiple benches in the Three Forks is going to come down to returns. Because obviously, if I put 2 wells in 2 benches in the Three Forks, I'd better, at least, get double the recovery or economically from a return standpoint, it doesn't make sense.

Right. So probably no wells next year in terms of a third or the fourth bench.

That's probably a 2015 type of...

No, I don't -- the majority of our acreage, if there is multiple bench, it appears to be in the second bench. The third and fourth bench, much more isolated and much smaller.